Method and apparatus for wellbore pressure control

ABSTRACT

A method includes conducting a downhole operation to access a reservoir, providing a control platform in communication with equipment units from different operational systems affecting bottom hole pressure in the downhole operation, and collecting into the control platform data from multiple operational systems used in the downhole operation. Another method further includes inputting at least one command into a single human-machine interface and sending the at least one command from the human-machine interface to a master controller for implementation of the command(s) through the control platform in order to operate the control platform through the single human-machine interface.

BACKGROUND

In a typical wellbore operation, a downhole drilling tool drills a borehole, or wellbore, into a rock or earth formation. A drilling system for use in drilling for oil, gas, and other hydrocarbons may include: a drilling rig, a drill string having its upper end mechanically coupled and suspended from the drilling rig, and a bottom hole assembly (“BHA”) mechanically coupled to the lower end of the drill string, where the BHA may include a drill bit at its lower end. The drill string is typically made up of segments of drill pipe that are coupled together, end-to-end, to form a long pipe string.

In a drilling system, a drilling fluid, called “mud,” is typically pumped from the surface, through the drill string to the drill bit. The mud exits through ports in the drill bit, where it cools and lubricates the drill bit and cleans away the drill cuttings from the bottom of the borehole. Additional tools near the bit (including, for example, motors, under reamers, rotary steerable system, measurement-while-drilling (“MWD”) tools, or logging-while-drilling (“LWD”) tools) may divert a portion of the fluid flow out to the annulus close to the bit, but the majority of the flow will pass through the bit. In offshore drilling, there may also be an additional flow path of fluid to a riser annulus through a riser boost system.

Success of a drilling operation depends on proper control of wellbore fluid pressure. The bottom hole pressure is a function of well depth, mud property, and operation conditions (the start or stop of equipment (pumps, drawworks, top drive), fluid flowing, choke position, etc). When the bottom hole pressure is too high, there is a risk of fracturing the formation, causing damage to the oil well and significant cost to repair. On the other hand, when the bottom hole pressure is too low, there is a risk of well flow (or “kick”), which could put the personnel, wellsite equipment and environment at risk. For example, during a drilling operation, when the mud pump stops in preparation for making a connection, there may be a negative pressure spike at the bottom hole as a result of stopping the pump. Similarly, when the mud pump starts, there may be a positive pressure spike at the bottom hole. As another example, when the drill bit goes on bottom, bottom hole pressure changes as a result of moving the whole drill string into the well.

Conventionally, bottom hole pressure is managed using a closed-loop circulation system, referred to as managed pressure drilling (“MPD”), where control of bottom hole pressure may be supplemented with a backpressure system. The backpressure system may include an arrangement of chokes and valves and a backpressure pump, where elements in the backpressure system may be operated to alter or maintain the bottom hole pressure. MPD mostly only controls choke position and/or the backpressure pump in the MPD system to affect the bottom hole pressure.

SUMMARY

This summary is provided to introduce a selection of concepts that are further described below in the detailed description. This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of the claimed subject matter.

In one aspect, embodiments of the present disclosure relate to a method that includes conducting a downhole operation to access a reservoir, providing a control platform in communication with equipment units from different operational systems affecting bottom hole pressure in the downhole operation, and collecting into the control platform data from multiple operational systems used in the downhole operation.

In another aspect, embodiments of the present disclosure relate to a method that includes conducting a downhole operation to access a reservoir, collecting of data from multiple operational systems used in the downhole operation, determining an equipment operation sequence to maintain a targeted bottom hole pressure for the downhole operation based on the data, using a master controller to access real-time control functions of equipment units from different operational systems in the downhole operation, and executing the equipment operation sequence using the master controller, the equipment operation sequence including a series of commands to operate one or more of the equipment units.

In yet another aspect, embodiments of the present disclosure relate to a drilling system that includes multiple operational systems, each operational system having equipment units designed to perform an operation of a downhole operation, a control platform in communication with the multiple operational systems, and a master controller in communication with control functions of the equipment units from different operational systems affecting wellbore pressure in the downhole operation.

Other aspects and advantages of the invention will be apparent from the following description and the appended claims.

BRIEF DESCRIPTION OF FIGURES

FIG. 1 shows an example of a drilling system according to embodiments of the present disclosure.

FIG. 2 shows a schematic of equipment used in MPD drilling system according to embodiments of the present disclosure.

FIG. 3 shows a schematic of an integrated control system according to embodiments of the present disclosure.

FIG. 4 shows a computing system in accordance with embodiments of the present disclosure.

DETAILED DESCRIPTION

The particulars shown herein are by way of example and for purposes of illustrative discussion of the examples of the subject disclosure only and are presented in the cause of providing what is believed to be the most useful and readily understood description of the principles and conceptual aspects of the subject disclosure. In this regard, no attempt is made to show structural details in more detail than is necessary, the description taken with the drawings making apparent to those skilled in the art how the several forms of the subject disclosure may be embodied in practice. Furthermore, like reference numbers and designations in the various drawings indicate like elements.

Embodiments of the present disclosure may provide improved control of managed pressure drilling (MPD). For example, embodiments of the present disclosure include a control platform to coordinate the operation of drilling equipment that could affect the bottom hole pressure. As used herein, the “control platform” may include a set of software functionality that is broadly applicable to many use-cases and may be designed to implement various specific problem sets. A control platform may be an operating system, an operating environment or a data bus, under which smaller application programs can be run to implement the various specific problem sets.

According to embodiments of present disclosure, a control platform may be provided in a drilling system having multiple operational systems, where operational systems may be in communication through the control platform. Each operational system has equipment units designed to perform an operation of a downhole operation. For example, an operational system may include a rig control system, which may be used to control major drilling equipment, such as a top drive, drawworks, mud pumps, and a trip tank and pump. Another operational system may be a fluid control system, which may be provided to control the management of mud (drilling fluid) for the downhole operation.

For example, whereas conventional methods of controlling bottom hole pressure may be limited to management of a MPD system to control a backpressure system, embodiments of the present disclosure may include controlling multiple systems and equipment therein that could contribute to change of bottom hole pressure, such as the start or the stop of a mud pump, the speed of drill string tripping in or out, the density of mud circulated through the drillstring are normally not considered as part of the automated MPD control.

FIG. 1 shows an example of a drilling system 100 that is equipped for communication between operational systems via a control platform. As shown in FIG. 1, the drilling system 100 includes a drill string 102 hanging from a derrick 106. The drill string 102 may extend through a rotary table into the well 110. A drill bit 112 is attached to the end of the drill string 102, and drilling is accomplished by rotating via the top drive 142 and allowing the weight of the drill string 102 to press down on the drill bit 112 via the Drawworks144 supporting the drill string 102. The drill bit 112 may be rotated by rotating the entire drill string 102 from the surface using the top drive 142. Alternatively, the drill bit 112 may be rotated by the rotary table (not shown) and the kelly (not shown). The drill bit 112 may alternatively be rotated independent of the drill string 102 by operating a downhole mud motor 116 above the drill bit 112.

While drilling, mud (drilling fluid) is pumped from mud pumps 118 on the surface 120 through the standpipe 122 and down the drill string 102. The mud in the drill string 102 is forced out through nozzles (not shown) in the face of the drill bit 112 and returned to the surface through the well annulus 124, i.e., the space between the well 110 and the drill string 102. One or more sensors or transducers 126 may be located in one or more measurement modules 127 in the bottom hole assembly of the drill string 102 to measure desired downhole conditions. For example, the transducer 126 may be a strain gage that measures weight-on-bit or a thermocouple that measures temperature at the bottom of the well 110. Separately, one or more sensors or transducers (not shown) may be located at surface to measure the drilling status, such as hookload, standpipe pressure, mud flow rate, return flow rate, etc. Additional sensors may be provided as necessary to measure other drilling and formation parameters such as those previously described.

Measurements from sensors downhole may be transmitted to the surface through the drilling mud in the drill string 102. For example, transducers 126 may send signals that are representative of the measured downhole condition to a downhole electronics unit 128. The signals from the transducers 126 may be digitized in an analog-to-digital converter. The downhole electronics unit 128 collects the binary digits, or bits, from the measurements from the transducers 126 and arranges them into data frames. Extra bits for synchronization and error detection and correction may be added to the data frames. The signal may be transmitted according to known techniques, such as by carrier waveform through the mud in the drill string 102. The various electronics associated with mud pulse telemetry is known and for clarity is not further described. A pressure transducer 132 on the standpipe 122 may detect changes in mud pressure and generate signals that are representative of these changes. The output of the pressure transducer 132 may be digitized in an analog-to-digital converter and processed by a signal processor 134 which recovers the symbols from the received waveform and then sends the data to a computer 138. Other methods of downhole communication may be employed such as data transmission via wired drill-pipe. Collected data from the drilling system may be transmitted to a control platform 140.

A control platform 140 is configured to communicate with and control the operation of various machinery in different operational systems. Operational systems may be designated in terms of a collective function of a plurality of equipment units that may contribute to performing the function. For example, a rig control system is an operational system including a plurality of equipment units that may be operated on the rig (e.g., derrick 106), such as top drive 142, drawwork 144, mud pump 118.A fluid control system is another example of an operational system, which could be used to control fluid (or mud) system to manage the tank volume, fluid density, etc.

Another operational system may be a managed pressure control system, which may be used to regulate the back pressure of return fluid flow from a downhole operation. Managed pressure control systems may include a plurality of equipment units that may contribute to controlling the flow of fluid returning from a downhole operation in order to control the bottom hole pressure. For example, managed pressure control systems may include flow control equipment connected together along a return flow line, where fluid returning from a downhole operation may flow through the managed pressure control system to return to the surface. Flow control equipment in a managed pressure control system may include, for example, a rotary control device (RCD), one or more chokes and/or other valves (e.g., a choke manifold), which may be operated to restrict or allow fluid flow to alter or maintain back pressure of the returning fluid, and/or a back pressure pump, which may provide a wide range control of the back pressure for the circulation system. In some embodiments, one or both of a fluid control system and a managed pressure control system may be built as part of a rig control system.

FIG. 2 shows a schematic of equipment used in MPD drilling system 200. In the example shown, the drilling system 200 is an offshore drilling system, where a well is drilled at the bottom of a body of water. However, similar drilling systems may be provided on land. As shown in FIG. 2, a drill string 210 may be extended through a riser 202 (extending from a drilling platform to the sea floor) and into a wellbore being drilled. A bottom hole assembly (BHA) including a drill bit for drilling the wellbore is not shown, but is disposed at an axial end of the drill string 210. Casing 204 may be provided along the wellbore wall as the wellbore is drilled. A blowout preventer (BOP) 220 may be provided at the well head. Different types of BOPs are known, but generally, BOPs are mechanical devices used to seal and control well production to prevent uncontrolled release of fluids (e.g., oil and/or gas) from the well.

A rotating control device (RCD) 230 may be provided above the BOP 220, where the drill string 210 may be passed through both the RCD 230 and BOP 220 to extend into the wellbore. An RCD may act as a flow diverter and a pressure control equipment unit in the drilling system. For example, the RCD 230 may provide an effective annular seal around the drill string 210 during drilling and tripping operations by packing off (sealing) around the drill string. An RCD may include a pressure-containing housing where one or more packer elements are supported between bearings and isolated by mechanical seals. In some embodiments, an active type RCD (using external hydraulic pressure to activate the sealing mechanism) may be used, where the sealing pressure may be increased as the annular pressure increases. In some embodiments, a passive type RCD (using a mechanical seal with the sealing action activated by wellbore pressure) may be used.

Within the context of this application, downhole operations generally refer to drilling, tripping (tripping in or out), reaming, wiper tripping, or another operation that utilizes operation of drilling string (e.g. translation or rotation). During drilling, drilling fluid may be passed through the drill string 210 to the bottom hole of the wellbore to help with the drilling operation (e.g., to cool the bit and clear cuttings from the bottom hole), and may return through the annulus formed between the casing 204 and drill string 210. With the MPD control system activated, the returning fluid (which may include drilling fluid and cuttings) may exit the wellbore and travel toward the surface via one or more flow paths, e.g., flow paths formed through the BOP, RCD, the annulus between the drill string 210 and riser 202, and diverter, return and/or outlet lines. As shown, an outlet line 232 may extend from the RCD 230 to a portion of a managed pressure control system, which may include one or more MPD chokes 234 and/or other valves (e.g., a choke manifold). Returning fluid may be routed through the outlet line 232 from the RCD 230, where the flow of the returning fluid may be controlled by one or more flow control equipment units (e.g., choke 234) in the managed pressure control system. When the MPD control system is not activated, returning fluid may be diverted from the annulus between the riser 202 and drill string 210 and routed through a return line 236 to return to the surface, or through a return line on bell nipper in a land rig (not shown).

Returning fluid from a downhole operation may be returned to the surface of the downhole operation, at which point, the returning fluid may be passed through separators to remove cuttings from the drilling fluid, may go through controlled disassociation of gas hydrates, may go through solid control equipment to further remove fine solids, may be routed to one or more mud storage areas (mud pits), and/or may be returned as drilling fluid to the mud pump.

Fluid control systems, managed pressure control systems and rig control systems are operational systems that may affect bottom hole pressure in a downhole operation. For example, a fluid control system may include additive management equipment, agitation equipment, solid control equipment and other mud circulation and storage equipment, which may be used to affect bottom hole pressure. A rig control system may include a mud pump, which may be used to alter the amount of fluid being pumped downhole, and drawworks, which may be used to alter the speed of drillstring into or out of the wellbore, thereby affecting the bottom hole pressure.

A control platform may be in communication with one or multiple operational systems of a drilling system affecting bottom hole pressure (such that signals may be sent and received between the multiple operational systems and control platform) and/or not affecting bottom hole pressure. In some embodiments, a control platform may be in communication with all operational systems of a drilling system having at least one electronically controlled equipment unit. By connecting/communicating the multiple operational systems through the control platform, the control platform may allow real time access to control each equipment unit of those operational systems having the capability to affect bottom hole pressure in a drilling system (e.g., mud pumps, drawworks, top drives, MPD chokes and/or other valves, back pressure pumps, trip tank pumps, and others). Control platforms may be in wired or wireless communication with operational systems of a drilling system.

A control platform may be used to effectively link control and data access of each operational system affecting bottom hole pressure in a downhole operation in order to provide coordinated MPD control. In other words, the control platform may act similar to a central command center that accesses information from each of the linked operational systems, and may base decisions for further action on the collective interpretation of the accessed information. In this manner, each linked operational system is in communication through the control platform.

FIG. 3 shows a schematic of coordinated MPD control system using a control platform according to embodiments of the present disclosure. As shown in FIG. 3, operational systems that may affect the wellbore pressure in a drilling system, including a fluid control system 310, a rig control system 320, and a managed pressure control system 330, may be in communication with a control platform 300. The control platform 300 is represented in the schematic by the lines connecting elements of the system together. However, the control platform 300 may physically be a system within a computing device including a connector and/or set of wires that allows for transportation of data between connected components. The control platform may also include software instructions for directing, analyzing, identifying and/or sorting data being transported through the control platform. For example, software instructions including communication protocols for the transportation of data through the control platform may be provided on a storage device and/or a computing component of the computing device in communication with the control platform.

Referring still to FIG. 3, a master controller 340 may be provided in the coordinated MPD control system and can access the real-time control function (e.g., a programmable logic controller (PLC)) of equipment units in the connected operational systems (fluid control system 310, rig control system 320, and managed pressure control system 330). The master controller 340 may include software instructions, e.g., one or more algorithms, that may, for example, process, analyze and/or store data being transported through the control platform 300. As an example, the master controller 340 may have algorithms to analyze data from various operational systems to identify different drilling events, such as fluid gain or loss, and automatically generate command commands in response to these events. Accordingly, the control platform may be referred to as a type of communication network, and the master controller may be a type of data processing system.

In some embodiments, a master controller (also may be referred to as a master MPD controller for controlling operational systems affecting wellbore pressure) may take the input of surface and/or downhole measurements, past, current and future operation sequences, predict potential pressure changes due to running an operation sequence, determine a control strategy to mitigate the effect of potential pressure changes to a targeted bottom hole pressure, and execute the control commands to achieve the pressure control goal. In order to perform selected control processes or functions, the master controller may access and use data collected into and transferred by the control platform.

Real time measurements from surface equipment and/or downhole equipment in a drilling system may be transmitted to a control platform (e.g., by wirelessly transmitting signals from the equipment to the control platform or by transmitting via wires from the equipment to the control platform). In some embodiments, measurements from equipment used in a drilling system (e.g., sensor data collected from one or more sensors used in the downhole operation, both from surface sensors and downhole sensors) and/or other data (e.g., operational state data indicating an on/off status of one or more components used in the downhole operation) may be transmitted to the control platform, either by automatic transmission or by manually inputting the data into the control platform. In some embodiments, real time measurements and/or other data (e.g., stored measurements and operational state data) for a downhole operation may be collected from separate wells (e.g., nearby wells drilled to access the same or a similar type reservoir) and transmitted to the control platform in a current downhole operation.

For example, referring to FIG. 1, a master controller may be provided in the control platform 140, where the master controller may transmit control signals and receive feedback from equipment units in communication with the control platform 140. For example, the master controller may send/receive signals to the top drive 142 to adjust and maintain drill string rotational speed (revolutions per minute (rpm)), the mud pump 118 to adjust the flow of drilling mud through the system, and the drawwork 144 to adjust and maintain weight-on-bit. The master controller may further communicate with the equipment in the fluid system to adjust the fluid density. The master controller may further communicate with the MPD system to adjust the position of choke. The control platform 140 and corresponding master controller may be configured to communicate and control different machinery which affects bottom hole pressure in a downhole operation.

According to some embodiments, a master controller may fuse measurements of the current state of a wellbore with physical or empirical reservoir models, information learned from previous wells drilled and surface measurements, and measurements from nearby wells to devise the control strategy to ensure a pressure control goal is met. The master controller may further fuse the measurement data from the current downhole operation to detect drilling events, and devise a control strategy to ensure a pressure control objective is met.

As mentioned above, data transferred through a control platform may include manually inputted data. Manually inputted data may be inputted through a human-machine interface (HMI) 360 provided at an operation control station in the control platform system. An HMI is an interface that an operator may use to interact with and control automation equipment.

Further, the operation control station may allow for an operator or other personnel to interact with the control systems, where commands from the HMI may be routed to the master MPD controller. For example, an operator or driller may manually input controls into the operation control station via the HMI 360, which may be routed through the control platform to the master controller 350. The master controller 350 may take into account manually inputted controls to determine an updated assessment of the operation of the downhole operation and/or to update other equipment control sequences effected by the manually inputted controls. In some embodiments, the master controller 350 may evaluate the impact of manual input, and coordinate the operation of other equipment to maintain a target bottom hole pressure. For example, if the user input is to trip out the drillstring at a certain speed, the master controller may analyze and determine the impact of the trip out operation on the bottom hole pressure, and automatically increase the pump rate to maintain the target bottom hole pressure. In some embodiments, the master controller 350 may merely pass the manually inputted controls to the designated control functions in the operational systems. For example, manually inputted controls related to an act affecting the bottom hole pressure in a downhole operation may be inputted through the HMI 360, which are then intercepted to a master MPD controller before being passed on to the corresponding control functions (e.g., PLCs) of equipment units in the designated operational systems affecting the bottom hole pressure. Manually inputted controls may include at least those inputs which could affect the bottom hole pressure, such as pump start, or change in flow rate, etc.

According to embodiments of the present disclosure, a control platform may include a single HMI for interacting with multiple operational systems in a downhole operation (e.g., in contrast to conventional drilling systems where each operational system may be provided with a separate HMI). In other words, a single HMI may allow an operator to interact with each operational system of a downhole operation that is in communication with the control platform. A single master controller may also be provided with a control platform. A master controller is a separate entity from the HMI (e.g., different software functionalities and different hardware components), although in implementation, the HMI and master controller may reside in the same computing system. A single master controller may receive information from different participants in the control platform, including information from each operational system, from the HMI, from job planning software, etc., and automatically make decisions to deliver commands to operational systems.

Referring again to FIG. 3, a high-level automation planner 350 may be provided in the coordinated MPD control system, where the automation planner 350 may include a series of software instructions to analyze collected data available in the control platform and generate conclusions based on the data analysis. For example, the automation planner 350 may include one or more algorithms or conditional computer programming (programming language including conditional statements or constructs that perform different computations or actions depending on whether a specified Boolean condition is true or false) that may identify collected data (e.g., type and value of the collected data) and analyze the collected data to determine its effects on the overall condition of the downhole operation. The automation planner may also use the collected data transmitted by each operational system to the control platform to identify drilling events, such as fluid loss or gain. The automation planner may receive a job program, such as operational goal and operation parameters. Based on the analysis and/or identified event, or the job program, the automation planner may generate one or more commands to control one or more aspects of the downhole operation in order to achieve a desired objective or goal. In some embodiments, the automation planner may include simulation software, which may use collected data to simulate all or a portion of the downhole operation. Based on the simulation(s), the automation planner may generate one or more commands to control one or more aspects of the downhole operation in order to achieve a desired objective or goal. An automation planner may automatically generate (without human interference) one or more commands based on data analysis and/or a selected objective of the downhole operation.

The automation planner 350 may have access to status data (e.g., rate of penetration, standpipe pressure, mud density, etc) being transported through the control platform 300. For example, the automation planner 350 may have access to data related to a downhole operation from each operational system to access a reservoir and/or data related to the reservoir collected from other sources (e.g., separately drilled wells to access the reservoir). Further, one or more objectives or goals for the downhole operation may be accessed by the automation planner 350, such as drilling to a certain depth, maintaining a certain bottom hole pressure, or others. The automation planner 350 may include software instructions to analyze any or all data collected related to a downhole operation (including, for example, data collected from a current drilling operation, data collected from separate but related drilling operations, and/or previously drilled wells), and use such analysis to determine differences, if any, between the current state of the downhole operation and the selected objectives or goals for the downhole operation.

Based on the collected data related to the downhole operation and one or more objectives for the downhole operation, the automation planner 350 may automatically create an equipment operation sequence, where an equipment operation sequence includes a series of commands to operate one or more equipment units in the downhole operation in order to achieve the downhole operation objective(s). Commands generated by the automation planner 350 (including an equipment operation sequence and/or one or more isolated commands) may be issued to the master controller 340 in order to be carried out. Namely, commands generated from the automation planner 350 may be sent to the master controller 340, which may then be sent to the control functions of designated machinery of corresponding operational system for execution of the commands. In such embodiments, one or more commands for operation of machinery in a downhole operation may be automatically produced by the automation planner 350 rather than, or in addition to, commands manually inputted or generated by an operator or other personnel (e.g., which may be manually inputted through the HMI 360).

In some embodiments, an automation planner 350 may include software instructions for optimizing one or more processes in a downhole operation. For example, data related to one or more processes in a downhole operation (e.g., tripping a drill string, drilling a distance through an identified type of formation, maintaining a selected bottom hole pressure) may be transferred through a control platform to the automation planner, where the automation planner may analyze the collected data. Upon analysis, the automation planner may determine optimized or more efficient operation conditions to achieve the process. From the determined optimized operation conditions, the automation planner may generate one or more commands for one or more equipment units to operate in a manner corresponding to, or to achieve, the determined optimized operation conditions.

For example, an automation planner may be used to optimize a process for maintaining a bottom hole pressure, where the automation planner may analyze data related to drilling fluid being pumped downhole, data related to a back-pressure system or a managed pressure control system (e.g., operational state data of one or more chokes or choke manifold, pump speed of a back-pressure pump, and others), data related to surface and/or downhole measurements for calculating bottom hole pressure, and others. Upon analysis of data related to the bottom hole pressure, the automation planner may determine optimized operation conditions to achieve the selected goal of maintaining a bottom hole pressure. For example, the automation planner may determine that the process may be more efficient by altering a position of one or more valves in the back-pressure system rather than or in addition to altering the density of drilling fluid being pumped downhole. From the determined optimized operation conditions, the automation planner may generate one or more commands to achieve the optimized operation conditions. The generated commands may be sent to a master controller, where the master controller may then send the commands to the designated control functions of equipment being commanded.

According to embodiments of the present disclosure, a high level automation planner may be used to interpret a job plan and issue commands, including an equipment operation sequence to control one or more operational systems (e.g., RCS, FCS, MPD system, etc). Commands from the automation planner may be routed to a master MPD controller, which may send the commands to designated machinery. This automation planner can access information about a reservoir, which may come from, for example, previously drilled wells, surface measurements (e.g., seismic measurements) and downhole measurements. Access to this information allows the automation planner to anticipate downhole factors that will affect wellbore pressure based on this understanding of the reservoir (e.g., knowledge in advance of a formation change, formation pressure change, formation mobility/permeability change, etc). The automation planner may issue commands to a master MPD controller that take into account this anticipated downhole behavior.

According to embodiments of the present disclosure, an automation program (including a set of software instructions) in an automation planner may receive its input from a well job program and create an equipment operation sequence based on the well job program. The automation program may create an equipment operation sequence based on the overall drilling objective (such as drilling to the target depth), and current operation states in a downhole operation. As described above, the automation program may be based on an understanding of the subsurface conditions gained from previously drilled wells, surface seismic measurements, and other collected data related to the downhole operation.

Drilling systems according to embodiments of the present disclosure may include multiple operational systems, where each operational system includes equipment units designed to perform an operation of a downhole operation, and an integrated control system designed to access data from operational systems in the drilling system and control bottom hole pressure in the downhole operation being performed by the drilling system.

Integrated control systems of the present disclosure may be designed to provide an integrated and central control of each operational system capable of affecting bottom hole pressure in a downhole operation. Such systems may be referred to as an integrated or coordinated MPD control system. In some embodiments, systems of the present disclosure may include a control platform in communication with multiple operational systems including operational systems affecting the bottom hole pressure in a downhole operation, and optionally, also operational systems not directly affecting the bottom hole pressure. By providing a control platform in communication with multiple operational systems, the control platform may be configured to receive data collected from a wider range of operational systems (compared to control platforms just in communication with individual operational systems) in a downhole operation, thereby providing a more comprehensive position of the downhole operation. In some embodiments, rather than, or in addition to, connecting (e.g., through a wireless or wired connection) a control platform with operational systems, data related to a downhole operation (including, e.g., data from operational systems and/or data collected from separately drilled wells) may be manually inputted or transferred to a control platform.

As discussed above, systems of the present disclosure may further include a master controller in communication with control functions of equipment units from different operational systems affecting wellbore pressure in the downhole operation. A master controller may have real time access to control the operation of each equipment unit of each operational system that could affect the bottom hole pressure. This real-time access may be enabled through a real-time data communication data bus (e.g., from the control platform) that links the master controller with relevant control systems (e.g., RCS, MPD systems, FCS, etc).

An HMI may be in communication with the master controller, which may allow a person to input data and/or commands into the integrated control system. This HMI may have access to all information from each operational system, such that it provides an integrated operation station to operate the downhole operation utilizing each operational system. Information from multiple operational systems may be displayed in this HMI as needed based on the state of operation. Inputted data and/or commands may be sent from the HMI to the master controller. In some embodiments, an integrated control system may include an automation planner, which may automatically generate one or more commands based on collected data and/or downhole operation objectives, and send the commands to the master controller for execution.

A master controller may provide the following: 1) Monitoring of the wellhead and/or bottom hole pressure and control of the operation of equipment to ensure the bottom hole pressure control goal is met; 2) Receive equipment commands from an operator or an equipment operation sequence from an automation program, analyze and predict corresponding impact to the bottom hole pressure, and devise a control strategy to ensure pressure control goal is met; 3) Execute the control strategy by delivering the control commands to each target equipment.

Equipment in a downhole operation sending and/or receiving signals to a control platform may be electronically controlled. Such equipment units may receive commands from a master controller in the integrated control system. In some embodiments, one or more equipment units in a downhole operation may be manually controlled (in addition to or instead of being electronically controlled). With such equipment units, an operator may manually control the equipment unit to achieve a desired command, and/or a master controller may provide a suggested command for the operator to manually control the equipment unit.

Methods of the present disclosure, may include conducting a downhole operation to access a reservoir, communicating a control platform with equipment units from different operational systems affecting bottom hole pressure in the downhole operation, and collecting into the control platform data from multiple operational systems used in the downhole operation. Equipment units may include at least one equipment unit in a managed pressure control system of the downhole operation and at least one equipment unit in a rig control system that could affect the downhole operation.

As mentioned above, data collected from the downhole operation may include, for example, data collected from a measurement device (e.g., sensor data collected from one or more sensors used in the downhole operation, or sensor data collected from surface that could be used to infer information about the downhole operation) and operational state data indicating an on/off status of one or more components which could be used to affect the downhole operation. Data collected from measurement devices may include, for example, outputs received from sensors used throughout the downhole operation, downhole telemetry equipment, seismic tools, and handheld measurement devices that may be brought to selected areas of the downhole operation by personnel (e.g., chemical detection devices, voltmeters, thermometers, etc.). Data collected from a measurement device could be used to infer the current pressure condition downhole, while operation state data could be used to anticipate its pending effect on the pressure condition downhole. Both of these types of data may be used to devise a control strategy to achieve a target pressure objective.

In some embodiments, collected data may include data related to a reservoir. For example, data related to a reservoir may include data collected from a current downhole operation conducted to access the reservoir as well as data collected from at least one separate drilling operation conducted to access the reservoir. Collected data related to a reservoir may be selected from at least one type of data collected from the downhole operation (e.g. reservoir pressure data, depth data, lithology data, etc. that could be used to correlate depth or geophysical information with offset wells), data collected from at least one separate drilling operation conducted to access the reservoir (e.g. reservoir pressure data, depth data, geophysical information that may be used to correlate with other offset wells in the same reservoir), and data collected at surface level above the reservoir. For example, data collected at surface level above the reservoir may include outputs received from surface equipment, such as seismic and magnetic data.

As used herein, collected data (data collected from a current downhole operation and/or, more broadly, data related to a reservoir) may include binary and/or numerical output from measurement devices as well as visual and/or in-person observations from equipment operation (e.g., operational state of equipment units; if a kick is observed; observed size, shape, color, and/or type of cuttings returned from drilling; atypical sounds coming from an equipment unit; etc.). For example, data may include outputs received from downhole measurement devices (e.g., from logging tools), formation testing results, results of laboratory analysis on fluids and/or formation samples, data collected from downhole fluid sampling and analysis, and outputs received from surface measurement devices. Further, data may include geophysical data (data collected from testing and analysis of formation samples, which may include seismic data, magnetic properties of tested formation samples, porosity and density of formation samples, and observational data from formation samples such as size, shape and color); drilling parameters (e.g., drilling rate, torque, vibration, drag, etc.); drilling fluid parameters (e.g., density, amount of cuttings being returned, flow rates, resistivity, chemical compositions, temperature and pressure); data related to cuttings being returned from a downhole operation (e.g., density, shape, size, amount being returned, etc.); well logging data (e.g., resistivity, conductivity, interval transit time, magnetic resonance, porosity, etc.); and data from direct pressure measuring devices.

Data collected from the surface and downhole from a downhole operation may be used to determine bottom hole pressure. Equipment state data collected from the surface of a downhole operation may be used to infer pending changes in bottom hole pressure of the downhole operation. Further, surface and downhole data collected from a separate drilling operation may be used to infer bottom hole pressure of a current downhole operation accessing a shared reservoir and/or to correlate (through depth or geophysical markers) depth or pressure information between a current wellbore and a separate well (e.g., offset wellbore).

Methods of the present disclosure may further include controlling an integrated control system through a single control station that has a single HMI (for a person to interact with different operational systems in a downhole operation), a single master controller and a single control platform, where the control platform may connect different operational systems of the downhole operation to the HMI and the master controller. Through this connected network, information from multiple operational systems in a downhole operation may be displayed or otherwise relayed to an operator, e.g., through the single HMI), and control/commands to the multiple operational systems may be implemented through the single HMI, via the master controller. For example, methods of the present disclosure may include operating a control platform through a single HMI, the HMI being in communication with a master controller, wherein operating includes inputting at least one command into the HMI, sending the at least one command from the HMI to the master controller to implement the command(s), and displaying information from at least one of the operational systems of the downhole operation on the HMI. In some embodiments, a single HMI may be used to operate all operational systems of a downhole operation (through the control platform), where information from different operational systems may be provided to the HMI to inform personnel of an overall drilling state or an event.

In some embodiments, methods may include providing an automation planner in the control platform, where the automation planner may have access to data related to the downhole operation. An equipment operation sequence may be created using the automation planner based on one or more drilling objectives, where the equipment operation sequence includes a series of commands to operate one or more of the equipment units, and where the equipment operation sequence may be issued to the master controller for execution. Further, an automation planner may generate a prediction of potential changes in the bottom hole pressure in a downhole operation based on collected data related to the downhole operation, wherein a generated equipment operation sequence may be further based on the prediction of potential changes in the bottom hole pressure. Control commands sent from the automation planner to a master controller in the control platform may be sent to at least one of the equipment units in the downhole operation to alter or maintain the bottom hole pressure.

According to some embodiments of the present disclosure, methods may include conducting a downhole operation to access a reservoir, collecting data from multiple operational systems related to the downhole operation and/or the reservoir, determining an equipment operation sequence to maintain a targeted bottom hole pressure for the downhole operation based on the collected data, using a master controller to access real-time control functions of equipment units from different operational systems in the downhole operation, and executing the equipment operation sequence using the master controller, where the equipment operation sequence includes a series of commands to operate one or more of the equipment units. Potential changes in bottom hole pressure in the downhole operation may be predicted based on the data from multiple operational systems, for example, by using software computations or prediction models or by using human calculations.

An equipment operation sequence may be determined by data from multiple operational systems used in the downhole operation with an automation planner, where the automation planner includes instructions to identify and analyze the data, including identifying the drilling events, such as loss and gain, and generating the equipment operation sequence from the automation planner based on the data. The equipment operation sequence generated from the automation planner may then be issued to a master controller for execution of the commands. In some methods, one or more of the commands of the equipment operation sequence may be inputted by an operator.

Integrated control systems according to embodiments of the present disclosure may be implemented on a computing system. For example, an operation control station may include one or more computing systems having an HMI built therein or connected thereto. Any combination of mobile, desktop, server, router, switch, embedded device, or other types of hardware may be used. For example, as shown in FIG. 4, a computing system 400 may include one or more computer processors 402, non-persistent storage 404 (e.g., volatile memory, such as random access memory (RAM), cache memory), persistent storage 406 (e.g., a hard disk, an optical drive such as a compact disk (CD) drive or digital versatile disk (DVD) drive, a flash memory, etc.), a communication interface 412 (e.g., Bluetooth interface, infrared interface, network interface, optical interface, etc.), and numerous other elements and functionalities.

The computer processor(s) 402 may be an integrated circuit for processing instructions. For example, the computer processor(s) may be one or more cores or micro-cores of a processor. A master controller according to embodiments of the present disclosure may be executed on a computer processor. The computing system 400 may also include one or more input devices 410, such as a touchscreen, keyboard, mouse, microphone, touchpad, electronic pen, or any other type of input device.

The communication interface 412 may include an integrated circuit for connecting the computing system 400 to a network (not shown) (e.g., a local area network (LAN), a wide area network (WAN) such as the Internet, mobile network, or any other type of network) and/or to another device, such as another computing device.

Further, the computing system 400 may include one or more output devices 408, such as a screen (e.g., a liquid crystal display (LCD), a plasma display, touchscreen, cathode ray tube (CRT) monitor, projector, or other display device), a printer, external storage, or any other output device. One or more of the output devices may be the same or different from the input device(s). The input and output device(s) may be locally or remotely connected to the computer processor(s) 402, non-persistent storage 404, and persistent storage 406. Many different types of computing systems exist, and the aforementioned input and output device(s) may take other forms.

Further, a single HMI may be provided with a computing system 400 for implementing methods disclosed herein. An HMI may include a screen, such as a touch screen, used as an input (e.g., for a person to input commands) and output (e.g., for display) of the computing system. In some embodiments, an HMI may also include switches, knobs, joysticks and/or other hardware components which may allow an operator to interact through the HMI with the drilling system.

Software instructions in the form of computer readable program code to perform embodiments of the disclosure may be stored, in whole or in part, temporarily or permanently, on a non-transitory computer readable medium such as a CD, DVD, storage device, a diskette, a tape, flash memory, physical memory, or any other computer readable storage medium. Specifically, the software instructions may correspond to computer readable program code that, when executed by a processor(s), is configured to perform one or more embodiments of the disclosure.

The computing system in FIG. 4 may implement and/or be connected to a data repository, such as a database, which may be used to store data collected from a drilling system according to embodiments of the present disclosure. A database is a collection of information configured for ease of data retrieval, modification, re-organization, and deletion.

The computing system of FIG. 4 may include functionality to present raw and/or processed data, such as results of comparisons and other processing performed by an automation planner. For example, data may be presented through a user interface provided by a computing device. The user interface may include a graphical user interface (GUI) that displays information on a display device, such as a computer monitor or a touchscreen on a handheld computer device. The GUI may include various GUI widgets that organize what data is shown as well as how data is presented to a user (e.g., data presented as actual data values through text, or rendered by the computing device into a visual representation of the data, such as through visualizing a data model).

The above description of functions presents only a few examples of functions performed by the computing system of FIG. 4. Other functions may be performed using one or more embodiments of the disclosure.

Although only a few examples have been described in detail above, those skilled in the art will readily appreciate that many modifications are possible in the examples without materially departing from this subject disclosure. Accordingly, all such modifications are intended to be included within the scope of this disclosure as defined in the following claims. In the claims, means-plus-function clauses are intended to cover the structures described herein as performing the recited function and not only structural equivalents, but also equivalent structures. Thus, although a nail and a screw may not be structural equivalents in that a nail employs a cylindrical surface to secure wooden parts together, whereas a screw employs a helical surface, in the environment of fastening wooden parts, a nail and a screw may be equivalent structures. It is the express intention of the applicant not to invoke 35 U.S.C. § 112(f) for any limitations of any of the claims herein, except for those in which the claim expressly uses the words ‘means for’ together with an associated function. 

What is claimed:
 1. A method, comprising: conducting a downhole operation to access a reservoir; providing a control platform in communication with equipment units from different operational systems affecting bottom hole pressure in the downhole operation; and collecting into the control platform data from multiple operational systems used in the downhole operation.
 2. The method of claim 1, wherein the equipment units comprise at least one equipment unit in a managed pressure control system of the downhole operation and at least one equipment unit in a rig control system of the downhole operation.
 3. The method of claim 1, wherein the data comprises sensor data collected from one or more sensors used in the downhole operation and operational state data indicating an on/off status of one or more components used in the downhole operation.
 4. The method of claim 1, further comprising collecting data from at least one separate drilling operation conducted to access the reservoir.
 5. The method of claim 1, further comprising sending control commands from a master controller in the control platform to at least one of the equipment units to alter or maintain the bottom hole pressure.
 6. The method of claim 5, further comprising operating the control platform through a single human-machine interface, the human-machine interface being in communication with the master controller, wherein operating comprises: inputting at least one command into the human-machine interface; sending the at least one command from the human-machine interface to the master controller; and displaying information from at least one of the operational systems on the human-machine interface.
 7. The method of claim 5, further comprising: providing an automation planner in the control platform, where the automation planner has access to data related to the downhole operation; creating an equipment operation sequence using the automation planner based on one or more drilling objectives, the equipment operation sequence comprising a series of commands to operate one or more of the equipment units; and issuing the equipment operation sequence to the master controller.
 8. The method of claim 7, wherein the data related to the downhole operation is selected from at least one of data from the downhole operation, data collected from at least one separate drilling operation conducted to access the reservoir, and data collected at surface level above the reservoir.
 9. The method of claim 7, wherein the automation planner generates a prediction of potential changes in the bottom hole pressure in the downhole operation based on the data related to the downhole operation, and wherein the equipment operation sequence is further based on the prediction of potential changes in the bottom hole pressure.
 10. A method, comprising: conducting a downhole operation to access a reservoir; collecting data from multiple operational systems used in the downhole operation; determining an equipment operation sequence to maintain a targeted bottom hole pressure for the downhole operation based on the data; using a master controller to access real-time control functions of equipment units from different operational systems in the downhole operation; and executing the equipment operation sequence using the master controller, the equipment operation sequence comprising a series of commands to operate one or more of the equipment units.
 11. The method of claim 10, further comprising predicting potential changes in bottom hole pressure in the downhole operation based on the data.
 12. The method of claim 10, further comprising collecting data from at least one separate drilling operation conducted to access the reservoir.
 13. The method of claim 10, wherein the data comprises data inputted through a human-machine interface.
 14. The method of claim 13, wherein the inputted data comprises an operator command to operate one or more of the equipment units, wherein the operator command is routed through the master controller before being sent to the control function of the one or more equipment units.
 15. The method of claim 10, wherein the operational systems are in communication through a control platform, the control platform comprising a communication data bus linking the master controller with the operational systems.
 16. The method of claim 10, wherein determining the equipment operation sequence comprises: accessing the data with an automation planner, the automation planner comprising instructions to identify and analyze the data; and generating the equipment operation sequence from the automation planner based on the data; wherein the equipment operation sequence generated from the automation planner is issued to the master controller for execution of the commands.
 17. The method of claim 10, wherein one or more of the commands of the equipment operation sequence is inputted by an operator.
 18. A drilling system, comprising: multiple operational systems, each operational system comprising equipment units designed to perform an operation of a downhole operation; a control platform in communication with the multiple operational systems; and a master controller in communication with control functions of the equipment units from different operational systems affecting wellbore pressure in the downhole operation.
 19. The drilling system of claim 18, further comprising a single human-machine interface in communication with the master controller.
 20. The drilling system of claim 18, wherein the operational systems affecting wellbore pressure comprise a rig control system, a fluid control system and a managed pressure control system. 